Hydraulic fracturing is a well-known technique for stimulating production from subterranean hydrocarbon-bearing formations. In a typical operation, an interval of a wellbore adjacent to a formation is perforated and fracturing fluid is pumped into the formation at a pressure sufficient to fracture the formation both laterally, away from the wellbore, and vertically, along the length of the wellbore. Propping agents such as sand or bauxite are usually mixed in with the fracturing fluid in order to enter the fractures and maintain them open once the pressure is reduced. This treatment enhances the productivity of the formation and thereby increases hydrocarbon production rates.
Hydraulic fracturing has been successfully employed in many types of hydrocarbon formations, particularly low permeability reservoirs which require stimulation to accelerate production to flow rates which make the reservoir economic to develop. Occasionally, conventional fracturing techniques have to be modified to stimulate a reservoir. For example, some reservoirs have many hydrocarbon bearing formations that are vertically stacked along the length of the wellbore and which are separated by essentially impermeable, non-hydrocarbon bearing formations. Techniques have been developed which permit successive fracturing of each of the formations. Temporary means are used to seal off the perforations adjacent to one formation that has been fractured while a subsequent fracture treatment is conducted at a different depth in the same formation or in another formation. Mechanical devices such as bridge plugs and packers have been used to separate treatment zones, and more recently, multi-zone fracturing using inexpensive ball sealers has been employed.
Although hydraulic fracturing technology has progressed to where many low permeability hydrocarbon formations can be economically produced, there are certain types of natural gas reservoirs which continue to defy economic fracturing exploitation; specifically, reservoirs which are characterized by discontinuous lenticular gas-bearing sand deposits of limited areal extent. These lenticular sands are also frequently "tight" which means they are characterized by low or very low permeability. Prime examples of such tight gas reservoirs are the various basins in the Rocky Mountain region of the western United States (Greater Green River, Piceance, Wind River and Uinta) which contain numerous lenticular, tight gas sandstones within thick formations. These four basins have been judged to be the largest undeveloped gas resource in the United States, containing as much as 227 trillion cubic meters (8,000 TCF) of recoverable gas. These enormous gas reserves remain substantially undeveloped because no economic method for developing these reserves has heretofore been developed.
Much attention has been directed at fracturing techniques for developing formations having tight, lenticular gas deposits. Because of the enormous reserve base of potentially recoverable gas, a significant amount of research has been performed by the U.S. Department of Energy, government and private research laboratories, universities and the private sector in an attempt to develop fracturing technology to economically exploit lenticular formations. To date, these efforts have been largely unsuccessful.
The approach initially attempted to access tight lenticular formations was nuclear stimulation. Under this program nuclear explosive devices were detonated within large diameter wellbores to generate a large zone of dendritic fractures in the zone surrounding the detonation. The largest such experiment was the nuclear detonation in a lenticular gas formation near Rio Blanco, Colo., equivalent to 90 kilotons of dynamite. In addition to the obvious environmental, health and safety concerns associated with nuclear stimulation, such experiments were not successful in releasing significant volumes of gas reserves. The lack of control over the explosive fracturing and the subsequent closure of the dendritic fractures caused the nuclear stimulation projects to fall far short of expected gas stimulation results.
In the early 1970's the next approach chosen to stimulate tight gas lenticular formations was a new process, termed massive hydraulic fracturing (MHF), which envisioned creating very long fractures up to 1.6 kilometers (one mile) or more in length using very large volumes of fracturing fluid and proppant. Under the sponsorship of the Department of Energy, a joint industry consortium tested MHF treatments in the Rio Blanco region. To illustrate this project, one fracture treatment injected 398,250 kg (878,000 lbs) of sand proppant into one 28 m (91 ft) section of the formation during an MHF experiment. Even though this MHF generated a dynamic fracture length of about 564 m (1,850 ft) and a propped fracture length of about 267 m (875 ft), the resulting stimulated gas rate was only 3,880 standard cubic meters/d (137 kscf/d) after 30 days of production. (As used herein the term dynamic fracture length means the length of one wing of a bi-winged fracture from the wellbore to one of the tips created by the fracturing fluid while the terms propped fracture length or simply fracture length is that distance from the wellbore reached by the proppant.) Five zones were stimulated during the Rio Blanco experiment with various sizes of MHFs. Stimulated production levels were disappointingly low, usually less than 5,600 m.sup.3 /d (200 kscf/d), with the highest observed post fracture production rate being about 6,230 m.sup.3 /d (220 kscf/d); well below the desired flow rate of about 42,500 m.sup.3 /d (1,500 kscf/d) after one year of production, which is needed to achieve economic production for the wells in question.
Unrelated to the Rio Blanco project, in the late 1970's enhancements in multi-stage fracturing were achieved in stimulating lenticular heavy oil formations Stimulation of Asphaltic Deep Wells and Shallow Wells in Lake Maracaibo, Venezuela, World Petroleum Conference 1979, Bucharest, Romania, P.D. 7(1)(the "WPC paper")!. These enhancements were achieved using ball sealer diverters. The WPC paper teaches that completing the wells with limited perforation intervals enables each stage of fracturing to open an independent fracture which is in communication with only one set of perforations. It was found that each stage of fracture treatment opened about 30 vertical meters (100 ft) of zone. Using low perforation shot densities of about three shots per meter (1 shot per foot) over 3 m (10 ft) combined with proper time release of the ball sealers permits stimulation of all of the oil sands penetrated by a given well. Although the WPC paper discusses multi-stage fracturing of heavy oil lenticular formations, it does not address methods or techniques for controlling fracture propagation in relationship to the size, distribution and placement of the oil sands. Because these oil sands have high permeabilities in the 1-100 mD range, their stimulation does not closely correspond to stimulating production from tight gas reservoirs characterized by lenticular deposits such as sand lenses. In fact, the WPC paper suggests that greater stimulation of the oil sands could be gained from longer fractures if an inexpensive, highly permeable proppant was used as an alternative to sand. However, as noted above, very long MHF fractures failed to achieve desired results in lenticular sand, tight gas reservoirs.
The failure of the Rio Blanco project led to the Multi-Well Experiment project (MWX) in the 1980's that explicitly studied hydraulic fracture shapes and flow capacities in an attempt to enhance gas stimulation benefits. MWX consisted of three wellbores placed about 46 m (150 ft) apart at total depth so that two of the wellbores could be used for close observation and monitoring of fracturing treatments done in the first wellbore. Most of the fracturing injections into the MWX wells were small to moderate in size so that the monitoring wells could sense signals from the entire fractured region. (For example, in one experiment the propped fracture length was only about 65 m (214 ft).) This work led to the conclusion that there was nothing inherently wrong with the hydraulic fractures formed in these tight gas sands, i.e., fracture lengths, widths, and heights were the expected size.
The MWX project was followed at the same site by the M-Site project that continued the measurement of hydraulic fracture parameters until the end of 1996. During this entire time, efforts have been directed at advancing existing technology to more economically exploit the Rocky Mountain lenticular sands. As described in SPE Paper 35,630 Advanced Technologies for Producing Massively Stacked Lenticular Sands, Apr. 28, 1996!, advanced stimulation techniques and the intersection of natural fractures, coupled with intensive infill well development, can enhance the prospects of commercial production from tight lenticular sands. This paper suggests separating the lenticular sands encountered by a well into a series of packages of 91 to 152 m (300 to 500 ft) of gross interval. In 610.sup.+ m (2000.sup.+ ft) of saturated gas zone for a typical well there would be four to seven such packages. The analysis in this paper concludes that completing wells in multiple zones correlates strongly with increases in production.
As to infill well development SPE 35,630 suggests that closer well spacing will increase total gas recovery, noting, for example, that at 40 acres per well 12 out of 16 wells would still penetrate separate sand bodies, i.e., no or limited interference or communication with the sands of an adjacent well. This limited interference occurs because the average areal extent of the lenticular sands in communication with the wells reviewed in SPE 35,630 is only about 22 acres. However, even with multiple zone fracturing and infill drilling, wells drilled with 40 acre spacing still would have a recovery efficiency of gas in place of only about 26%. Thus nearly three fourths of the original gas in place would remain unrecovered using the approach suggested in SPE 35,630. Although the SPE paper suggests well spacing down to 20 acres might further enhance recovery, it fails to disclose methods for controlling the stimulation techniques to capture larger quantities of the original gas in place or the relationship between the stimulation technique and the spacing of the wells. Therefore, what is needed is a well stimulation method for substantially enhancing production from reservoirs characterized by tight gas, lenticular deposits such that they become commercially exploitable gas fields.